In the past, all onshore or offshore oil and gas wells were completed by cementing a casing string in a well and then using a workover rig to perform various operations including the running of a tubing string in the well through which oil or gas was produced. Workover rigs are often equipped with a tank into which completion liquids or well liquids are discharged, such as when the well is swabbed.
Many years ago, the practice called tubingless completions developed where, in onshore wells, a string of tubing was cemented in the well bore and using a slick line unit, swabbing unit or logging truck to complete the well. Typically, drilling mud is present inside the tubing string when the completion unit arrives at the well site because drilling mud is used to pump the second plug of a cementing operation downwardly into the well. Because of the nature of tubingless completions, the only things that have to be done in a completion attempt is run a cased hole log, perforate the desired interval and swab the well to relieve the hydrostatic load on the productive formation. Thus, the production string is swabbed or the well produced, at some stage of the proceedings, so the drilling mud is discharged from the well, either into an earthen pit, metal tank or vacuum truck.
Current high tech onshore wells, both vertical and horizontal, are completed differently. Typically, a string of pipe is cemented in the well bore and the well completed with a coiled tubing unit. Most high tech wells are completed in tight sands or shales which were not considered productive until the advent of multiple high volume frac jobs so many completion operations include fracing multiple zones penetrated by the well bore. In one conventional technique, a first lower zone is perforated and fraced, a bridge plug is set above the fraced zone, a second higher zone is perforated and fraced, a bridge plug is set above the second fraced zone and this process is repeated to perforate and frac a series of productive zones. In the process of drilling out the bridge plugs or other completion equipment, any frac sand deposited on top of a bridge plug is circulated out of the well. There are other completion techniques for modern high tech onshore wells but all of them use a coiled tubing unit to remove frac sand from the well and to drill up completion equipment inside the well.
A completion liquid, typically 2% potassium chloride in water, is typically pumped down the coiled tubing to rotate the bit and circulate drilled solids. Typically, circulation is up the annulus between the coiled tubing and the inside of the casing string although sometimes it is down the annulus and up the tubing. Universally, a vacuum truck containing uncontaminated completion liquid is a source for the liquid pumped into the well. Completion liquid and drilled solids are discharged into a second vacuum truck. When the first vacuum truck empties, the second vacuum truck is normally full so the flow connections leading from the well are changed so the first vacuum truck becomes the collection truck and a third vacuum truck having a fresh load of uncontaminated completion liquid is connected as the supply source. The amount of completion liquid used in these type wells depends on the number of bridge plugs that have to be drilled out, the amount of frac sand collected on top of the bridge plugs and the like but it would not be unusual to consume 1000 barrels of completion liquid in completing a modern high tech well. This has its cost because the completion liquid must be bought, the vacuum trucks hired and the completion liquid disposed of.
It is not known how many wells have been completed using a coiled tubing unit in this manner. What is known is this technique has been used extensively by knowledgeable and experienced companies and field personnel—no inexperienced person is given the responsibility of such efforts. Estimates of knowledgeable people vary between tens of thousands and hundreds of thousands of wells have been completed using coiled tubing units in this manner in the last decade.
Relating to another feature of the method and apparatus disclosed herein, when the bore hole of an onshore or offshore oil or gas well is drilled, drilling mud is circulated down the drill string and up the annulus between the drill string and the well bore. This accomplishes several purposes, one of which is the removal of rock particles, known as cuttings or drilled solids, from the face of the bit so the bit is working on uncut rock rather than grinding away on chips that have already broken off the rock face. When the drilling mud reaches the surface, it may be handled in a variety of ways, depending usually on the size of the rig and the depth of the well being drilled.
In the past, when drilling shallow onshore wells with small rigs, the drilling mud and cuttings were discharged into an earthen pit where larger particles drop out of suspension. The mud passes into a second pit where smaller particles drop out of suspension, chemicals are added to the mud and a pump delivers the treated mud back to the drill string. This practice is now been superseded by the use of mud tanks because regulatory agencies, in most jurisdictions, have basically outlawed the use of earthen pits.
Current practice has been to adopt, for all onshore wells, what was heretofore used only in deeper onshore wells drilled with larger rigs. In other words, the drilling mud and cuttings are discharged into a tank where the mud is treated by removing drilled solids from the mud so chemicals may be added before the mud is pumped back into the drill stem. Mud tanks are of a variety of different types but all have some means of removing drilled solids from liquid mud and discharging drilled solids from the tank. Usually, some of the drilled solids drop out of suspension simply by a reduction in velocity of the mud and then the mud may be delivered to centrifuges or cyclones where smaller particles are removed. U.S. Pat. No. 7,160,474 discloses one such mud tank where drilled solids settle out and are then removed from the mud tank by one or more augers. The drilled solids removed from this tank, or from any tank, are in the form of a thick slurry comprising a substantial amount of drilled solids, a considerable amount of liquid mud sorbed on the drilled solids and some free liquid. Considerable effort may be spent to recover as much of the liquid mud as feasible because it contains expensive materials and reduces the volume of material and thus its disposal cost. Thus, drilled solid slurries are often sent through a cyclone, centrifuge or similar device to remove a greater quantity of liquid than can be removed by settling alone.
In the past, drilled solid slurries, from onshore mud tanks were put in what is known as a reserve pit which comprised a earthen wall enclosing a ground level storage area. After the well was completed and the drilled solids slurry dried out, the earthen wall was breached and the remaining material and the earthen wall were mixed and spread over the land. This practice has been basically outlawed where the drilling mud is an oil based mud and these drilled solids, in most jurisdictions, must now be disposed of in a more formal manner. The situation is different where the drilling mud is a water based mud and different states have different requirements.
At the current time, drilled solids from onshore wells drilled with oil based muds are discharged from the mud tank into a shale bin or receptacle on or near the mud tank. Sand or dirt is mixed with a drilled solids slurry to sorb the remaining free liquid so the resultant material may be delivered to, and disposed at, a landfill or similar disposal site. As used herein, the word “sorb” is intended to be a generic term to include “absorb” and “adsorb” because it may not be clear exactly which mechanism is at work. Commercial landfills, either municipally owned, owned by public companies or privately owned, often will not accept slurries, i.e. the material has to have no free liquid. Slurries may have to be disposed of at hazardous material depositories which involve considerable cost.
The amount of drilled solids trucked away from a well site during the drilling process is quite substantial and a large proportion of the disposed material is the sand or dirt added to the drilled solids to sorb any free liquid. In a typical 9000′ onshore well, about three hundred fifty cubic yards of drilled solids—sand mixture may be hauled away to a landfill for disposal.
One can readily calculate the volume of drilled solids from a wellbore, within a reasonable degree of error, by calculating the volume of the drilled hole. For example, a typical 9000′ well in South Texas might drill a 12¼″ surface hole to 2000′ and set surface pipe, drill a 9⅝″ hole to 7000′ and set 7⅝″ intermediate casing and drill a 6¼″ hole to T.D. A calculation of the volume of rock removed from the earth using a 15% washout factor for the surface hole reveals that the rock volume removed from the earth, based on the above assumptions, is about 190 cubic yards. The volume of the drilled hole is always smaller than the amount of cuttings generated because the cuttings, by definition, are not packed as closely as the undrilled rock. This typically amounts to an increase in volume by 20-30%. Thus, in the above example, the volume of the cuttings would likely be about 225-245 cubic yards. The amount of sand or dirt varies significantly, but it may be as much as an additional 40-50% by volume. Thus, a large fraction of the difference between a calculation of rock volume drilled and the amount of material actually hauled away will be the amount of sand or dirt used to soak up free liquid.
As used herein, the phrase drilled solids means rock cuttings, debris from comminuted well parts, frac sand, mill scale and other debris found in wells at a time when they are completed.
Disclosures of interest relative to this invention are found in U.S. Pat. Nos. 2,714,932; 2,756,827; 2,941,783; 3,282,342; 3,291,218; 3,384,169; 3,393,743; 3,429,375; 3,554,280; 4,429,754; 4,440,243; 5,132,025; 5,232,475; 5,311,939; 5,419,399; 6,769,491; 6,863,809; 7,021,389; 7,048,058; 7,048,060; 7,152,682; 7,160,474 and 7,350,582 along with printed patent application 2008/0060821.